Enhanced hydrocarbon recovery from a single well by electrical resistive heating of a single inclusion in an oil sand formation

ABSTRACT

The present invention is a method and apparatus for enhanced recovery of petroleum fluids from the subsurface by electrical resistive heating of the oil sand formation and the heavy oil and bitumen in situ, by electrically energizing vertical inclusion planes containing electrically conductive proppant. The inclusion is propagated into a portion of the formation having a Skempton&#39;s B parameter of greater than 0.95 exp(−0.04 p′)+0.008 p′, where p′ is a mean effective stress in MPa at the depth of the inclusion. Multiple propped vertical inclusions at various azimuths are constructed from the well. Electrodes are placed in the well in electrical contact with the inclusions and an alternating direction current is passed through the proppant. By electrically resistive heating of the inclusion, the formation is heated by conduction and associated hydrocarbon fluids are lowered in viscosity and drain by gravity back to the well and produced to the surface. By controlling the reservoir temperature and pressure, a particular fraction of the in situ hydrocarbon reserve is extracted and water inflow into the heated zone is minimized.

TECHNICAL FIELD

The present invention generally relates to enhanced recovery ofpetroleum fluids from the subsurface by electrical resistive heating ofelectrically conductive proppant in vertical inclusions, thereuponheating the oil sand formation and the viscous heavy oil and bitumen insitu, more particularly to a method and apparatus to extract aparticular fraction of the in situ hydrocarbon reserve by controllingthe reservoir temperature and pressure, while also minimizing waterinflow into the heated zone and well bore, resulting in increasedproduction of petroleum fluids from the subsurface formation.

BACKGROUND OF THE INVENTION

Heavy oil and bitumen oil sands are abundant in reservoirs in many partsof the world such as those in Alberta, Canada, Utah and California inthe United States, the Orinoco Belt of Venezuela, Indonesia, China andRussia. The hydrocarbon reserves of the oil sand deposit is extremelylarge in the trillions of barrels, with recoverable reserves estimatedby current technology in the 300 billion barrels for Alberta, Canada anda similar recoverable reserve for Venezuela. These vast heavy oil(defined as the liquid petroleum resource of less than 20° API gravity)deposits are found largely in unconsolidated sandstones, being highporosity permeable cohensionless sands with minimal grain to graincementation. The hydrocarbons are extracted from the oils sands eitherby mining or in situ methods.

The heavy oil and bitumen in the oil sand deposits have high viscosityat reservoir temperatures and pressures. While some distinctions havearisen between tar or oil sands, bitumen and heavy oil, these terms willbe used interchangeably herein. The oil sand deposits in Alberta, Canadaextend over many square miles and vary in thickness up to hundreds offeet thick. Although some of these deposits lie close to the surface andare suitable for surface mining, the majority of the deposits are atdepth ranging from a shallow depth of 150 feet down to several thousandsof feet below ground surface. The oil sands located at these depthsconstitute some of the world's largest presently known petroleumdeposits. The oil sands contain a viscous hydrocarbon material, commonlyreferred to as bitumen, in an amount that ranges up to 15% by weight.Bitumen is effectively immobile at typical reservoir temperatures. Forexample at 15° C., bitumen has a viscosity of ˜1,000,000 centipoise.However at elevated temperatures the bitumen viscosity changesconsiderably to be ˜350 centipoise at 100° C. down to ˜10 centipoise at180° C. The oil sand deposits have an inherently high permeabilityranging from ˜1 to 10 Darcy, thus upon heating, the heavy oil becomesmobile and can easily drain from the deposit.

Solvents applied to the bitumen soften the bitumen and reduce itsviscosity and provide a non-thermal mechanism to improve the bitumenmobility. Hydrocarbon solvents consist of vaporized light hydrocarbonssuch as ethane, propane or butane or liquid solvents such as pipelinediluents, natural condensate streams or fractions of synthetic crudes.The diluent can be added to steam and flashed to a vapor state or bemaintained as a liquid at elevated temperature and pressure, dependingon the particular diluent composition. While in contact with thebitumen, the saturated solvent vapor dissolves into the bitumen. Thisdiffusion process is due to the partial pressure difference between thesaturated solvent vapor and the bitumen. As a result of the diffusion ofthe solvent into the bitumen, the oil in the bitumen becomes diluted andmobile and will flow under gravity. The resultant mobile oil may bedeasphalted by the condensed solvent, leaving the heavy asphaltenesbehind within the oil sand pore space with little loss of inherent fluidmobility in the oil sands due to the small weight percent (5-15%) of theasphaltene fraction to the original oil in place. Deasphalting the oilfrom the oil sands produces a high grade quality product by 3°-5° APIgravity. If the reservoir temperature is elevated the diffusion rate ofthe solvent into the bitumen is raised considerably being two orders ofmagnitude greater at 100° C. compared to ambient reservoir temperaturesof ˜15° C.

In situ methods of hydrocarbon extraction from the oil sands consist ofcold production, in which the less viscous petroleum fluids areextracted from vertical and horizontal wells with sand exclusionscreens, CHOPS (cold heavy oil production system) cold production withsand extraction from vertical and horizontal wells with large diameterperforations thus encouraging sand to flow into the well bore, CSS(cyclic steam stimulation) a huff and puff cyclic steam injection systemwith gravity drainage of heated petroleum fluids using vertical andhorizontal wells, steamflood using injector wells for steam injectionand producer wells on 5 and 9 point layout for vertical wells andcombinations of vertical and horizontal wells, SAGD (steam assistedgravity drainage) steam injection and gravity production of heatedhydrocarbons using two horizontal wells, VAPEX (vapor assisted petroleumextraction) solvent vapor injection and gravity production of dilutedhydrocarbons using horizontal wells, and combinations of these methods.

Cyclic steam stimulation and steamflood hydrocarbon enhanced recoverymethods have been utilized worldwide, beginning in 1956 with thediscovery of CSS, huff and puff or steam-soak in Mene Grande field inVenezuela and for steamflood in the early 1960s in the Kern River fieldin California. These steam assisted hydrocarbon recovery methodsincluding a combination of steam and solvent are described in U.S. Pat.No. 3,739,852 to Woods et al, U.S. Pat. No. 4,280,559 to Best, U.S. Pat.No. 4,519,454 to McMillen, U.S. Pat. No. 4,697,642 to Vogel, and U.S.Pat. No. 6,708,759 to Leaute et al. The CSS process raises the steaminjection pressure above the formation fracturing pressure to createfractures within the formation and enhance the surface area access ofthe steam to the bitumen. Successive steam injection cycles reenterearlier created fractures and thus the process becomes less efficientover time. CSS is generally practiced in vertical webs, but systems areoperational in horizontal wells, but have complications due to localizedfracturing and steam entry and the lack of steam flow control along thelong length of the horizontal well bore.

Descriptions of the SAGD process and modifications are described in U.S.Pat. No. 4,344,485 to Butler, and U.S. Pat. No. 5,215,146 to Sanchez andthermal extraction methods in U.S. Pat. No. 4,085,803 to Butler, U.S.Pat. No. 4,099,570 to Vandergrift, and U.S. Pat. No. 4,116,275 to Butleret al. The SAGD process consists of two horizontal wells at the bottomof the hydrocarbon formation, with the injector well locatedapproximately 10-15 feet vertically above the producer well. The steaminjection pressures exceed the formation fracturing pressure in order toestablish connection between the two wells and develop a steam chamberin the oil sand formation. Similar to CSS, the SAGD method hascomplications, albeit less severe than CSS, due to the lack of steamflow control along the long section of the horizontal well and thedifficulty of controlling the growth of the steam chamber.

A thermal steam extraction process referred to a HASDrive (heatedannulus steam drive) and modifications thereof heat and hydrogenate theheavy oils in situ in the presence of a metal catalyst. Sec U.S. Pat.No. 3,994,340 to Anderson et al., U.S. Pat. No. 4,696,345 to Hsueh, U.S.Pat. No. 4,706,751 to Gondouin, U.S. Pat. No. 5,054,551 to Duerksen, andU.S. Pat. No. 5,145,003 to Duerksen. It is disclosed that at elevatedtemperature and pressure the injection of hydrogen or a combination ofhydrogen and carbon monoxide to the heavy oil in situ in the presence ofa metal catalyst will hydrogenate and thermal crack at least a portionof the petroleum in the formation.

Thermal recovery processes using steam require large amounts of energyto produce the steam, using either natural gas or heavy fractions ofproduced synthetic crude. Burning these fuels generates significantquantities of greenhouse gases, such as carbon dioxide. Also, the steamprocess uses considerable quantities of water, which even though may bereprocessed, involves recycling costs and energy use. Therefore a lessenergy intensive oil recovery process is desirable.

Solvents applied to the bitumen soften the bitumen and reduce itsviscosity and provide a non-thermal mechanism to improve the bitumenmobility. Hydrocarbon solvents consist of vaporized light hydrocarbonssuch as ethane, propane or butane or liquid solvents such as pipelinediluents, natural condensate streams or fractions of synthetic crudes.The diluent can be added to steam and flashed to a vapor state or bemaintained as a liquid at elevated temperature and pressure, dependingon the particular diluent composition. While in contact with thebitumen, the saturated solvent vapor dissolves into the bitumen. Thisdiffusion process is due to the partial pressure difference in thesaturated solvent vapor and the bitumen. As a result of the diffusion ofthe solvent into the bitumen, the oil in the bitumen becomes diluted andmobile and will flow under gravity. The resultant mobile oil may bedeasphalted by the condensed solvent, leaving the heavy asphaltenesbehind within the oil sand pore space with little loss of inherent fluidmobility in the oil sands due to the small weight percent (5-15%) of theasphaltene fraction to the original oil in place. Deasphalting the oilfrom the oil sands produces a high grade quality product by 3°-5° APIgravity. If the reservoir temperature is elevated the diffusion rate ofthe solvent into the bitumen is raised considerably being two orders ofmagnitude greater at 100° C. compared to ambient reservoir temperaturesof ˜15° C.

Solvent assisted recovery of hydrocarbons in continuous and cyclic modesare described including the VAPEX process and combinations of steam andsolvent plus heat. See U.S. Pat. No. 4,450,913 to Allen et al, U.S. Pat.No. 4,513,819 to Islip et al, U.S. Pat. No. 5,407,009 to Butler et al,U.S. Pat. No. 5,607,016 to Butler, U.S. Pat. No. 5,899,274 to Frauenfeldet al, U.S. Pat. No. 6,318,464 to Mokrys, U.S. Pat. No. 6,769,486 to Limet al, and U.S. Pat. No. 6,883,607 to Nenniger et al. The VAPEX processgenerally consists of two horizontal wells in a similar configuration toSAGD; however, there are variations to this including spaced horizontalwells and a combination of horizontal and vertical wells. The startupphase for the VAPEX process can be lengthy and take many months todevelop a controlled connection between the two wells and avoidpremature short circuiting between the injector and producer. The VAPEXprocess with horizontal wells has similar issues to CSS and SAGD inhorizontal wells, due to the lack of solvent flow control along the longhorizontal well bore, which can lead to non-uniformity of the vaporchamber development and growth along the horizontal well bore.

Direct heating and electrical heating methods for enhanced recovery ofhydrocarbons from oil sands and oil shales have been disclosed incombination with steam, hydrogen, catalysts and/or solvent injection attemperatures to ensure the petroleum fluids gravity drain from theformation and at significantly higher temperatures (300° to 400° rangeand above) to pyrolysis the oil shales. See U.S. Pat. No. 2,780,450 toLjungström, U.S. Pat. No. 4,597,441 to Ware et al, U.S. Pat. No.4,926,941 to Glandt et al, U.S. Pat. No. 5,046,559 to Glandt, U.S. Pat.No. 5,060,726 to Glandt et al, U.S. Pat. No. 5,297,626 to Vinegar et al,U.S. Pat. No. 5,392,854 to Vinegar et al, U.S. Pat. No. 6,722,431 toKaranikas et al. In situ combustion processes have also been disclosedsee U.S. Pat. No. 5,211,230 to Ostapovich et al, U.S. Pat. No. 5,339,897to Leaute, U.S. Pat. No. 5,413,224 to Laali, and U.S. Pat. No. 5,954,946to Klazinga et al.

In situ processes involving downhole heaters are described in U.S. Pat.No. 2,634,961 to Ljungström, U.S. Pat. No. 2,732,195 to Ljungström, U.S.Pat. No. 2,780,450 to Ljungström. Electrical heaters are described forheating viscous oils in the forms of downhole heaters and electricalheating of tubing and/or casing, see U.S. Pat. No. 2,548,360 to Germain,U.S. Pat. No. 4,716,960 to Eastlund et al, U.S. Pat. No. 5,060,287 toVan Egmond, U.S. Pat. No. 5,065,818 to Van Egmond, U.S. Pat. No.6,023,554 to Vinegar and U.S. Pat. No. 6,360,819 to Vinegar. Flamelessdownhole combustor heaters are described, see U.S. Pat. No. 5,255,742 toMikus, U.S. Pat. No. 5,404,952 to Vinegar et al, U.S. Pat. No. 5,862,858to Wellington et al, and U.S. Pat. No. 5,899,269 to Wellington et al.Surface fired heaters or surface burners may be used to heat a heattransferring fluid pumped downhole to heat the formation as described inU.S. Pat. No. 6,056,057 to Vinegar et al and U.S. Pat. No. 6,079,499 toMikus et al.

The thermal and solvent methods of enhanced oil recovery from oil sands,all suffer from a lack of surface area access to the in place bitumen.Thus the reasons for raising steam pressures above the fracturingpressure in CSS and during steam chamber development in SAGD, are toincrease surface area of the steam with the in place bitumen. Similarlythe VAPEX process is limited by the available surface area to the inplace bitumen, because the diffusion process at this contact controlsthe rate of softening of the bitumen. Likewise during steam chambergrowth in the SAGD process the contact surface area with the in placebitumen is virtually a constant, thus limiting the rate of heating ofthe bitumen. Therefore both methods (heat and solvent) or a combinationthereof would greatly benefit from a substantial increase in contactsurface area with the in place bitumen. Hydraulic fracturing of lowpermeable reservoirs has been used to increase the efficiency of suchprocesses and CSS methods involving fracturing are described in U.S.Pat. No. 3,739,852 to Woods et al, U.S. Pat. No. 5,297,626 to Vinegar etal, and U.S. Pat. No. 5,392,854 to Vinegar et al. Also during initiationof the SAGD process overpressurized conditions are usually imposed toaccelerate the steam chamber development, followed by a prolonged periodof underpressurized condition to reduce the steam to oil ratio.Maintaining reservoir pressure during heating of the oil sands has thesignificant benefit of minimizing water inflow to the heated zone and tothe well bore.

Electrical resistive heating of oil shale and oil sand formationsutilizing a hydraulic fracture filled with an electrically conductivematerial are described in U.S. Pat. No. 3,137,347 to Parker, involving ahorizontal hydraulic fracture filled with conductive proppant and withthe use of two (2) wells to electrically energizing the fracture andraise the temperature of the oil shale to pyrolyze the organic matterand produce hydrocarbon from a third well, in U.S. Pat. No. 5,620,049 toGipson et al. with a single well configuration in a hydrocarbonformation predominantly a vertical fracture filled with conductivetemperature setting resin coated proppant and the electric currentpasses through the conductive proppant to a surface ground and thesingle well is completed to raise the temperature of the oil in-situ toreduce its viscosity and produce hydrocarbons from the same well, inU.S. Pat. No. 6,148,911 to Gipson et al. with a single wellconfiguration in a gas hydrate formation with predominantly a horizontalfracture filled with conductive proppant and the electric current passesthrough the conductive proppant to a surface ground, raising thetemperature of the formation to release the methane from the gashydrates and the single well is completed for methane production, inU.S. Pat. No. 7,331,385 to Symington et al, in U.S. Pat. No. 7,631,691to Symington et al. and in Canadian Patent No. 2,738,873 to Symington etal. all with a predominantly vertical fracture filled with conductiveproppant and the conductive fracture is electrically energized bycontact with at least two (2) wells or in the case of a single wellpresumably through the well and surface ground with the oil shale raisedto a temperature to pyrolyze the organic matter into produciblehydrocarbons, with the electrically conductive fracture composed ofelectrically conductive proppant and non-electrically conductivenon-permeable cement. The single well systems described above all sufferfrom low efficiency and high energy loss due to the current passesthrough a significant distance of the formation from the conductivefracture to the surface ground. Also the systems with two or morewellbores do not disclosed how the electrode to conductive fracturecontact will be other than a point contact resulting in significantenergy loss and overheating at such a contact.

It is well known that extensive heavy oil reservoirs are found informations comprising unconsolidated, weakly cemented sediments.Unfortunately, the methods currently used for extracting the heavy oilfrom these formations have not produced entirely satisfactory results.Heavy oil is not very mobile in these formations, and so it would bedesirable to be able to form increased permeability planes in theformations and by placing electrically conductive proppant in theseplanes, and by passing an electric current through the propped planes,heating the formation and thus increase the mobility of the heavy oil inthe formation and by drainage through the permeable planes to thewellbore for production up the well.

However, techniques used in hard, brittle rock to form fractures thereinare typically not applicable to ductile formations comprisingunconsolidated, weakly cemented sediments. The method of controlling theazimuth of a vertical hydraulic planar inclusion in formations ofunconsolidated or weakly cemented soils and sediments by slotting thewell bore or installing a pre-slotted or weakened casing at apredetermined azimuth has been disclosed. The method disclosed that avertical hydraulic planar inclusion can be propagated at apre-determined azimuth in unconsolidated or weakly cemented sedimentsand that multiple orientated vertical hydraulic planar inclusions atdiffering azimuths from a single well bore can be initiated andpropagated for the enhancement of petroleum fluid production from theformation. See U.S. Pat. No. 6,216,783 to flocking et al, U.S. Pat. No.6,443,227 to flocking et al, U.S. Pat. No. 6,991,037 to Hocking, U.S.Pat. No. 7,404,441 to Hocking, U.S. Pat. No. 7,640,975 to Cavender etal. U.S. Pat. No. 7,640,982 to Schultz et al., U.S. Pat. No. 7,748,458to Hocking, U.S. Pat. No. 7,814,978 to Steele et al., U.S. Pat. No.7,832,477 to Cavender et al., U.S. Pat. No. 7,866,395 to Hocking, U.S.Pat. No. 7,950,456 to Cavender et al., U.S. Pat. No. 8,151,874 toSchultz et al. The method disclosed that a vertical hydraulic planarinclusion can be propagated at a pre-determined azimuth inunconsolidated or weakly cemented sediments and that multiple orientatedvertical hydraulic planar inclusions at differing azimuths from a singlewell bore can be initiated and propagated for the enhancement ofpetroleum fluid production from the formation. It is now known thatunconsolidated or weakly cemented sediments behave substantiallydifferent from brittle rocks from which most of the hydraulic fracturingexperience is founded.

The methods disclosed above find especially beneficial application inductile rock formations made up of unconsolidated or weakly cementedsediments, in which it is typically very difficult to obtain directionalor geometric control over inclusions as they are being formed. Weaklycemented sediments are primarily frictional materials since they haveminimal cohesive strength. An uncemented sand having no inherentcohesive strength (i.e., no cement bonding holding the sand grainstogether) cannot contain a stable crack within its structure and cannotundergo brittle fracture. Such materials are categorized as frictionalmaterials which fail under shear stress, whereas brittle cohesivematerials, such as strong rocks, fail under normal stress.

The term “cohesion” is used in the art to describe the strength of amaterial at zero effective mean stress. Weakly cemented materials mayappear to have some apparent cohesion due to suction or negative porepressures created by capillary attraction in fine grained sediment, withthe sediment being only partially saturated. These suction pressureshold the grains together at low effective stresses and, thus, are oftencalled apparent cohesion.

The suction pressures are not true bonding of the sediment's grains,since the suction pressures would dissipate due to complete saturationof the sediment. Apparent cohesion is generally such a small componentof strength that it cannot be effectively measured for strong rocks, andonly becomes apparent when testing very weakly cemented sediments.

Geological strong materials, such as relatively strong rock, behave asbrittle materials at normal petroleum reservoir depths, but at greatdepth (i.e. at very high confining stress) or at highly elevatedtemperatures, these rocks can behave like ductile frictional materials.Unconsolidated sands and weakly cemented formations behave as ductilefrictional materials from shallow to deep depths, and the behavior ofsuch materials are fundamentally different from rocks that exhibitbrittle fracture behavior. Ductile frictional materials fail under shearstress and consume energy due to frictional sliding, rotation anddisplacement.

Conventional hydraulic dilation of weakly cemented sediments isconducted extensively on petroleum reservoirs as a means of sandcontrol. The procedure is commonly referred to as “Frac-and-Pack.” in atypical operation, the casing is perforated over the formation intervalintended to be fractured and the formation is injected with a treatmentfluid of low gel loading without proppant, in order to form the desiredtwo winged structure of a fracture. Then, the proppant loading in thetreatment fluid is increased substantially to yield tip screen-out ofthe fracture. In this manner, the fracture tip does not extend further,and the fracture and perforations are backfilled with proppant.

The process assumes a two winged fracture is formed as in conventionalbrittle hydraulic fracturing. However, such a process has not beenduplicated in the laboratory or in shallow field trials. In laboratoryexperiments and shallow field trials what has been observed is chaoticgeometries of the injected fluid, with many cases evidencing cavityexpansion growth of the treatment fluid around the well and withdeformation or compaction of the host formation.

Weakly cemented sediments behave like a ductile frictional material inyield due to the predominantly frictional behavior and the low cohesionbetween the grains of the sediment. Such materials do not “fracture”and, therefore, there is no inherent fracturing process in thesematerials as compared to conventional hydraulic fracturing of strongbrittle rocks.

Linear elastic fracture mechanics is not generally applicable to thebehavior of weakly cemented sediments. The knowledge base of propagatingviscous planar inclusions in weakly cemented sediments is primarily fromrecent experience over the past ten years and much is still not knownregarding the process of viscous fluid propagation in these sediments.

Accordingly, there is a need for a method and apparatus for enhancingthe extraction of hydrocarbons from oil sands in a single well and inmultiple wells by direct electrical resistive heating of electricallyconductive permeable vertical inclusions combined with steam, gas and/orsolvent injection or a mixture thereof and controlling the subsurfaceenvironment, both temperature and pressure to optimize the hydrocarbonextraction in terms of produced rate, efficiency and produced productquality, as well as limit water inflow into the process zone.

SUMMARY OF THE INVENTION

The present invention is a method and apparatus for enhanced recovery ofpetroleum fluids from the subsurface by electrical resistive heating ofthe oil sand formation and the heavy oil and bitumen in situ, byelectrically energizing vertical inclusion planes containingelectrically conductive proppant. In one embodiment of this invention,multiple propped vertical inclusions at various azimuths are constructedfrom a single well and propagate into the oil sand formation and filledwith a highly electrically conductive proppant. An upper portion of thewell is hydraulically connected to the formation and provides for a sinkfor mobile formation and injected fluids. This pore pressure sinkattracts the lower propagating inclusion and ensures the inclusionpropagates upward in the formation and connects with the well at theupper hydraulically open section. Electrodes are placed in the well inelectrical contact with the lowermost and uppermost portions of theinclusions and an alternating direction current is passed through theproppant contained in the inclusions. By electrically resistive heatingof the inclusions, the formation is heated by conduction and associatedhydrocarbon fluids are lowered in viscosity and drain by gravity back tothe well to be produced to the surface.

The heating of the formation and in place heavy oil and bitumen is viaheat conduction from the electrically resistive heated inclusions and ispredominantly circumferential, i.e. orthogonal to the propped verticalinclusions. To limit upward growth of the process and/or to limit lossof heat by conduction to overlying formations, a non condensing gas canbe injected to remain in the uppermost portions of the heated processzone.

Although the present invention contemplates the formation of verticalpropped inclusions which generally extend laterally away from a verticalor near vertical well penetrating an earth formation and in a generallyvertical plane, those skilled in the art will recognize that theinvention may be carried out in earth formations wherein the fracturesand the well bores can extend in directions other than vertical.

Therefore, the present invention provides a method and apparatus forenhanced recovery of petroleum fluids from the subsurface byelectrically resistive heating propped electrical conductive permeableinclusions, thereupon heating the oil sand formation and the viscousheavy oil and bitumen in situ, more particularly to a method andapparatus to extract a particular fraction of the in situ hydrocarbonreserve by controlling the reservoir temperature and pressure, whilealso minimizing water inflow into the heated zone and well boreresulting in increased production of petroleum fluids from thesubsurface formation.

Other objects, features and advantages of the present invention willbecome apparent upon reviewing the following description of thepreferred embodiments of the invention, when taken in conjunction withthe drawings and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic isometric view of a well system and associatedmethod embodying principles of the present invention;

FIG. 2 is a schematic isometric view of the well system with a singlelower propagating inclusion with an upper section of the wellhydraulically connected to the formation;

FIG. 3 is a schematic isometric view of the well system completed with asingle inclusion that extends upward to the upper open section of thewell.

DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENT

Several embodiments of the present invention are described below andillustrated in the accompanying drawings. The present invention involvesa method and apparatus for enhanced recovery of petroleum fluids fromthe subsurface by electrical resistive heating of propped verticalinclusions in the oil sand formation, and thus heating the oil sandformation and the heavy oil and bitumen in situ by conduction. Multiplepropped vertical inclusions at various azimuths are constructed from thewell into the oil sand formation and filled with a electricallyconductive proppant. Electrodes are placed in the well, and analternating current passes through the electrically conductive proppantcontained in the inclusions, thus heating the inclusion by electricalresistive heating and in turn heating the formation and fluids bythermal conduction. The low viscosity heated hydrocarbon liquids drainby gravity and are produced to the surface up the well.

It is well known that extensive heavy oil reservoirs are found informations comprising unconsolidated, weakly cemented sediments.Unfortunately, the methods currently used for extracting the heavy oilfrom these formations have not produced entirely satisfactory results.Heavy oil is not very mobile in these formations, and so it would bedesirable to be able to form increased permeability planes in theformations and by placing electrically conductive proppant in theseplanes, and by passing an alternating electric current through thepropped planes, giving rise to electrically resistive heating of theproppant, and heating the formation by thermal conduction and thusincrease the mobility of the heavy oil in the formation and by gravitydrainage through the permeable planes to the wellbore for production upthe well.

Representatively illustrated in FIG. 1 is a well system 10 andassociated method which embody principles of the present invention. Thesystem 10 is particularly useful for producing heavy oil 42 from aformation 14. The formation 14 may comprise unconsolidated and/or weaklycemented sediments for which conventional fracturing operations are notwell suited. The term “heavy oil” is used herein to indicate relativelyhigh viscosity and high density hydrocarbons, such as bitumen. Heavy oilis typically not recoverable in its natural state (e.g., without heatingor diluting) via wells, and may be either mined or recovered via wellsthrough use of steam and solvent injection, in situ combustion, etc.Gas-free heavy oil generally has a viscosity of greater than 100centipoise and a density of less than 20 degrees API gravity (greaterthan about 900 kilograms/cubic meter).

As depicted in FIG. 1, a single vertical well has been drilled into theformation 14 and the well casing 11 has been cemented in the formation14. The term “casing” is used herein to indicate a protective lining fora wellbore. Any type of protective lining may be used, including thoseknown to persons skilled in the art as liner, casing, tubing, etc.Casing may be segmented or continuous, jointed or unjointed, conductiveor non-conductive made of any material (such as steel, aluminum,polymers, composite materials, etc.), and may be expanded or unexpanded,etc.

The casing string 11 has an expansion device 12, an open section 15 anda sump section 13 interconnected therein. The open section 15 of thewell could be a perforated section of the easing, a screen, slottedliner, etc providing hydraulic connection between the upper portion ofthe well 15 and the formation 14. The open section 15 of the well ismaintained at a lower pressure and independently of the injected fluid22 pressure. The expansion device 12 operates to expand the casingstring 11 radially outward and thereby dilate the formation 14 proximatethe devices, in order to initiate forming of generally vertical andplanar inclusions 1.8, extending outwardly from the wellbore at variousazimuths. Suitable expansion devices for use in the well system 10 aredescribed in U.S. Pat. Nos. 6,216,783, 6,330,914, 6,443,2.27, 6,991,037,7,404,441, 7,640,975, 7,640,982, 7,748,458, 7,814,978, 7,832,477,7,866,395, 7,950,456 and 8,151,874. The entire disclosures of theseprior patents are incorporated herein by this reference. Other expansiondevices may be used in the well system 10 in keeping with the principlesof the invention.

Once the device 12 is operated to expand the casing string 11 radiallyoutward, fluid 22 is forced into the dilated formation 14 to propagatethe inclusions 18 into the formation. It is not necessary for theinclusions 18 to be formed simultaneously. Shown in FIG. 1 is an eight(8) wing inclusion well system 10, with eight (8) inclusions 18 formed.The well system 10 does not necessarily need to consist of eight (8)inclusions at the same depth orientated at various azimuths, but couldconsist of one, two, three, four, five, six or even seven verticalplanar inclusions at various azimuths at the same depth, with suchchoice of the number of inclusions constructed depending on theapplication, formation type and/or economic benefit.

Typically, the inclusions 18 are constructed with each wing of the eight(8) inclusions 18 injected independently of the others. As theinclusions 18 are propagated into the formation 14, the upper opensection 15 of the well acts as a pore pressure sink and thus attractsand accelerates the upward propagation of the inclusions 18, so as toextend up to this open section 15. The formation 14 pore space maycontain a significant portion of immobile heavy oil or bitumen generallyup to a maximum oil saturation of 90%; however, even at these very highoil saturations of 90%, i.e. very low water saturation of 10%, themobility of the formation pore water is quite high, due to its viscosityand the formation permeability. The open section 15 allows mobileformation pore fluids and the injected fluid 22 to enter the well at 15at a reduced pressure, with 15 being at a lower pressure and independentof the injected fluid 22 pressure. Upon the inclusions 18 reaching theupper open section 15, its upward tip propagation rate will be reducedsignificantly. The well system 10 is shown with inclusions 18constructed at only a single depth, this well system 10 is cited as onlyone example of the invention, since there could be alternate forms ofthe invention containing numerous of upper inclusions constructed atprogressively shallower depths, depending on the formation thickness,the distribution of hydrocarbons within the formation 14, and/oreconomic benefit.

The injected fluid 22 carries the proppant to the extremes of theinclusions 18. Upon propagation of the inclusions 18 to their requiredlateral and vertical extent, the thickness of the inclusions 18 may needto be increased by utilizing the process of tip screen out. The tipscreen out process involves modifying the proppant loading and/or injectfluid 22 properties to achieve a proppant bridge at the inclusion tips.The injected fluid 22 is further injected after tip screen out, butrather then extending the inclusion laterally or vertically, theinjected fluid 22 widens, i.e. thickens, and fills the inclusion fromthe inclusion tips back to the well bore.

The behavioral characteristics of the injected viscous fluid 22 arepreferably controlled to ensure the propagating viscous inclusionsmaintain their azimuth directionality, such that the viscosity of theinjected fluid 22 and its volumetric rate are controlled within certainlimits depending on the formation 14 and the specific gravity and sizedistribution of the proppant 20. For example, the viscosity of theinjected fluid 22 is preferably greater than approximately 100centipoise. However, if foamed fluid is used, a greater range ofviscosity and injection rate may be permitted while still maintainingdirectional and geometric control over the inclusions. The viscosity andvolumetric rate of the injected fluid 22 needs to be sufficient totransport the electrically conductive proppant 20 to the extremities ofthe inclusions. The size distribution of the proppant 20 needs to bematched with that of the formation 14, to ensure formation fines do notmigrate into the propped pack inclusion during hydrocarbon production.Typical size distribution of the proppant would range from #12 to #20U.S. Mesh for oil sand formations, with an ideal proppant being ceramicbeads coated with a electrically conductive resin, of which oneparticularly suitable conductive resin comprises phenol formaldehydecontaining fine graphite particles. Such a resin is heat hardenable attemperatures of around 60° C. or higher, thus capable of mechanicallybinding the proppant together 21 without loss of permeability of thepropped inclusion.

The well system 10, has electrodes 33, 34 placed inside of the casingand in electrical contact with the conductive proppant 20. Theseelectrodes 33, 34 are connected via insulated cables 31, 32 to analternating direction current power source 30. Upon energizing theelectrical power source 30, current passes through the proppant 20 fromthe top to the bottom of the inclusions 18 and by electrical resistiveheating raises the temperature of the proppant 20 in the inclusions 18.At elevated temperature the conductive resin heat hardens to bind theproppant particles together at their contacts 21, without impacting theproppant pack permeability of the inclusions 18. The resistive heatpropagates circumferentially from the inclusions 18 and conductivelyheats the formation 14 and its associated fluids. Heated heavy oil andbitumen will thus be mobilized and flow under gravity towards the welland enter the sump 13 and pumped to surface via a PCP (progressivecavity pump), ESP (electrical submersible primp), gas lift or naturallift 41, depending on operating temperatures, pressures and depth, via aproduction tubing 40.

The selected range of temperatures and pressures to operate the processwill depend on reservoir depth, ambient conditions, quality of the inplace heavy oil and bitumen, and the presence of nearby water bodies.The process can be operated at a low temperature range of ˜100° C. for aheavy oil rich oil sand deposit and at a moderate temperature range of˜150°-180° C. for a bitumen rich oil sand deposit, basically to reducethe heavy oil and bitumen viscosity and thus mobilized the in place oil.However, the process can be operated at much higher temperatures >270°C. to pyrolysis the in place hydrocarbon in the presence of H₂, COand/or catalysts. Thus the proppant could contain such catalysts, orthese catalysts could be incorporated into a canister in line with theproduction tubing in the well. Such catalysts are really available asHDS (hydrodesulfurization) metal containing catalysts, and FCC (fluidcatalytic cracking) rare earth aluminum silica catalysts.

The operating pressure of the process may be selected to closely matchthe ambient reservoir conditions to minimize water inflow into theprocess zone and the well bore by the injection of steam, gas orvaporized solvent. The process zone can be injected with a vaporizedhydrocarbon solvent, such as ethane, propane or butane and mixed with adiluent gas, such as methane, nitrogen and carbon dioxide. The solventwill contact the in situ bitumen at the edge of the process zone,diffusive into and soften the bitumen, so that it flows by gravity tothe well bore. Dissolved solvent and product hydrocarbon are producedand further solvent and diluent gas injected into the process zone. Theelevated temperature of the process zone will significantly acceleratethe diffusion process of the solvent diffusing into the bitumen comparedto ambient reservoir conditions. The solvent and diluent gas will beinjected at near reservoir pressures to minimize water inflow into theprocess zone. The solvent vapor in the injection gas is maintainedsaturated at or near its dew point at the process operating temperaturesand pressures.

The formation 14 could be comprised of relatively hard and brittle rock,but the system 10 and method find especially beneficial application inductile rock formations made up of unconsolidated or weakly cementedsediments, in which it is typically very difficult to obtain directionalor geometric control over inclusions as they are being formed.

However, the present disclosure provides information to enable thoseskilled in the art of hydraulic fracturing, soil and rock mechanics topractice a method and system 10 to initiate and control the propagationof a viscous fluid in weakly cemented sediments, and importantly for thepropagating inclusion to intersect and coalesce with earlier placedpermeable inclusions and thus form a continuous planar inclusion on aparticular azimuth from within a single well or between multiple wells.

The system and associated method are applicable to formations of weaklycemented sediments with low cohesive strength compared to the verticaloverburden stress prevailing at the depth of interest. Low cohesivestrength is defined herein as no greater than 3 MegaPasca (MPa) plus 0.4times the mean effective stress (p′) in MPa at the depth of propagation.

c<3 MPa+0.4p′  (1)

where c is cohesive strength in MPa and p′ is mean effective stress inthe formation.

Examples of such weakly cemented sediments are sand and sandstoneformations, mudstones, shales, and siltstones, all of which haveinherent low cohesive strength. Critical state soil mechanics assists indefining when a material is behaving as a cohesive material capable ofbrittle fracture or when it behaves predominantly as a ductilefrictional material.

Weakly cemented sediments are also characterized as having a softskeleton structure at low effective mean stress due to the lack ofcohesive bonding between the grains. On the other hand, hard strongstiff rocks will not substantially decrease in volume under an incrementof load due to an increase in mean stress.

In the art of poroelasticity, the Skempton B parameter is a measure of asediment's characteristic stiffness compared to the fluid containedwithin the sediment's pores. The Skempton B parameter is a measure ofthe rise in pore pressure in the material for an incremental rise inmean stress under undrained conditions.

In stiff rocks, the rock skeleton takes on the increment of mean stressand thus the pore pressure does not rise, i.e., corresponding to aSkempton B parameter value of at or about 0. But in a soft soil, thesoil skeleton deforms easily under the increment of mean stress and,thus, the increment of mean stress is supported by the pore fluid underundrained conditions (corresponding to a Skempton B parameter of at orabout 1).

The following equations illustrate the relationships between theseparameters in equations denoted as (2) as follows:

Δu=BΔp

B=(K _(u) −K)/(αK _(u))

α=1−(K/K _(s))  (2)

where Δu is the increment of pore pressure. B the Skempton B parameter,Δp the increment of mean stress, K_(u) is the undrained formation bulkmodulus, K the drained formation bulk modulus, α is the Biot-Willisporoelastic parameter, and K_(s) is the hulk modulus of the formationgrains. In the system and associated method, the bulk modulus K of theformation for inclusion propagation is preferably less thanapproximately 5 GPa.

For use of the system 10 and method in weakly cemented sediments,preferably the Skempton B parameter is as follows with p′ in MPa:

B>0.95exp(−0.04p′)+0.008p′  (3)

The system and associated method are applicable to formations of weaklycemented sediments (such as tight gas sands, mudstones and shales) wherelarge extensive propped vertical permeable drainage planes are desiredto intersect thin sand lenses and provide drainage paths for greater gasproduction from the formations° in weakly cemented formations containingheavy oil (viscosity>1.00 centipoise) or bitumen (extremely highviscosity>100,000 centipoise), generally known as oil sands, proppedvertical permeable drainage planes provide drainage paths for coldproduction from these formations, and access for steam, solvents, oils,and heat to increase the mobility of the petroleum hydrocarbons and thusaid in the extraction of the hydrocarbons from the formation. In highlypermeable weak sand formations, permeable drainage planes of largelateral length result in lower drawdown of the pressure in thereservoir, which reduces the fluid gradients acting towards thewellbore, resulting in less drag on fines in the formation, resulting inreduced flow of formation fines into the wellbore.

Proppant is carried by the injected fluid, resulting in a highlypermeable planar inclusion. Such proppants are typically clean sand orspecialized manufactured particles (generally ceramic in composition),and depending on the size composition, closure stress and proppant type,the permeability of the fracture can be controlled. Electricallyconductive proppant can consist of metal coated ceramics, metalproppant, calcined petroleum coke, graphite beads, green or blacksilicon carbide, boron carbide, metal fiber, shaving or platelets, ornon-conductive sands, glass or ceramics with electrically conductiveresin or metal coating, or a mixture thereof to achieve the desiredelectrical conductivity, permeability and also to limit flow back of theproppant from the propped inclusion into the well bore during productionof the hydrocarbons from the formation. The permeability of the proppedinclusions 18 will typically be orders of magnitude greater than theformation 14 permeability, generally at least by two orders ofmagnitude. As regards the electrical conductivity of the proppedinclusions 18, the electrical conductivity needs to be greater than theformation 14 electrical conductivity, but not too great whereas electricenergy is lost by excessive short-circuiting between the electrodes, butan optimum value to achieve optimum, efficient and economical resistiveheating of the inclusions 18.

The injected fluid 22 varies depending on the application and can bewater, oil or multi-phased based gels. Aqueous based fracturing fluidsconsist of a polymeric gelling agent such as solvatable (or hydratable)polysaccaride, e.g. galactomannan gums, glycomannan gums and cellulosederivatives. The purpose of the hydratable polysaccharides is to thickenthe aqueous solution and thus act as viscosifiers, i.e. increase theviscosity by 100 times or more over the base aqueous solution. Across-linking agent can be added which further increases the viscosityof the solution. The borate ion has been used extensively as across-linking agent for hydrated guar gums and other galactomannans, seeU.S. Pat. No. 3,059,909 to Wise. Other suitable cross-linking agents arechromium, iron, aluminum, and zirconium (see U.S. Pat. No. 3,301,723 toChrisp) and titanium (see U.S. Pat. No. 3,888,312 to Tiner et al). Abreaker is added to the solution to controllably degrade the viscousfracturing fluid. Common breakers are enzymes and catalyzed oxidizerbreaker systems, with weak organic acids sometimes used.

An enlarged scale isometric view of the system 10 is representativelyillustrated in FIG. 2. This view depicts the system 10 during thepropagation of only one of the inclusions 18, to provide a clearerdescription of the process used to construct the system 10. The viscousfluid propagation process in these sediments involves the unloading ofthe formation 14 in the vicinity of the tips 23, 24, 25 of thepropagating viscous fluid 22, causing dilation of the formation 14,which generates pore pressure gradients towards this dilating zone. Asthe formation 14 dilates at the tips 23, 24, 25 of the advancing viscousfluid 22, the pore pressure decreases dramatically at the tips,resulting in increased pore pressure gradients surrounding the tips.

The pore pressure gradients at the tips 23, 24, 25 of the inclusion 18result in the liquefaction, cavitation (degassing) or fluidization ofthe formation 14 immediately surrounding the tips. That is, theformation 14 in the dilating zone about the tips 23, 24, 25 acts like afluid since its strength, fabric and in situ stresses have beendestroyed by the fluidizing process, and this fluidized zone in theformation immediately ahead of the viscous fluid 22 propagating tips 23,24, 25 is a planar path of least resistance for the viscous fluid topropagate further. In at least this manner, the system 10 and associatedmethod provide for directional and geometric control over the advancinginclusions 18.

The behavioral characteristics of the injected viscous fluid 22 arepreferably controlled to ensure the propagating viscous fluid does notoverrun the fluidized zone and lead to a loss of control of thepropagating process. Thus, the viscosity of the fluid 22 and thevolumetric rate of injection of the fluid should be controlled to ensurethat the conditions described above persist while the inclusions 18 arebeing propagated through the formation 14. The propagation rate of theinclusion 18 due to the injected fluid 22, varies depending ondirection, in general due to gravitation effects, the lateral tip 23propagation rate is generally much greater than the upward tip 24propagation rate and the downward tip 25 propagation rate. However,these tips 23, 24, 25 propagation rates can change due toheterogeneities in the formation 14, pore pressure gradients especiallyassociated with pore pressure sinks, and stress, stiffness and strengthcontrasts in the formation 14.

During propagation of the inclusion 18, the pore pressure in the overallformation will rise due to the injection of the fluid 22. As theinclusion 18 propagates, the upper open section 15 of the well acts as apore pressure sink and mobile formation pore fluids and injected fluid22 flows towards 15 as shown by 29. The open section 15 thus attractsand accelerates the upward tip 24 propagation rate of the inclusion 18.The inclusion 18 grows upward towards the depth of the open section 15,and upon reaching that depth its upward tip 24 propagation rate dropssignificantly.

Referring further to an enlarged scale isometric view of the system 10is representatively illustrated in FIG. 3. This view depicts the system10 during the completion of only one of the inclusion 18, to provide aclearer description of the process used to construct the system 10. Theinclusion 18 has been constructed to its final dimension, and uponreaching the depth of the open section 15, slows in its upward tip 24propagation rate due to fluid loss 29, and thus extends furtherlaterally, since it lateral tip 23 is not restricted by fluid loss 29 asis its upward tip 24. The inclusion 18 is now completed to its fulllateral extent as shown and is increased in thickness if necessary byutilizing tip-screen out.

Finally, it will be understood that the preferred embodiment has beendisclosed by way of example, and that other modifications may occur tothose skilled in the art without departing from the scope and spirit ofthe appended claims.

1. A method of improving production of hydrocarbons from a subterraneanformation of weakly cemented sediments, the method comprising the stepsof: a) propagating a first substantially vertical inclusion into theformation at a first depth and in a first preferential direction from asubstantially vertical wellbore intersecting the formation, wherein thefirst vertical inclusion is filled with an injected fluid includingelectrically conductive proppant particles; b) locating an open sectionof the wellbore at a second depth displaced from the first depth; c)maintaining the open section at a reduced pressure; d) propagating thefirst inclusion vertically to the second depth of the open section; e)passing an electric current through the inclusion by electrodes placedin the wellbore and heating the formation in a process zone in thevicinity of the first inclusion; and f) producing the heatedhydrocarbons up the wellbore.
 2. The method of claim 1, wherein thesecond depth of the open section of the wellbore is below the firstdepth.
 3. The method of claim 1, wherein the method includes propagatinga plurality of inclusions at varying azimuths.
 4. The method of claim 1,wherein the proppant particles range in size from #4 to #100 U.S. meshand are ceramic beads substantially coated with an electricallyconductive resin.
 5. The method of claim 4, wherein the resin is phenolformaldehyde containing fine graphite particles and is heat hardenable,with resin present in an amount sufficient to consolidate the proppant,but insufficient to fill the openings between the proppant.
 6. Themethod of claim 1, wherein the proppant particles range in size from #4to #100 U.S. mesh and are selected from a group of conductive materialssuch as metals, melt alloys, metal oxides, metal salts, metal-containingcatalysts, calcined petroleum coke or graphite beads, green or blacksilicon carbide, boron carbide or a mixture thereof.
 7. The method ofclaim 1, wherein the proppant particles range in size from #4 to #100U.S. mesh and are selected from a group of non-conductive materials suchas ceramics, glass and sands coated with a conductive layer either beingmetal, metal oxide, metal salts, conductive resins or mixtures thereof.8. The method of claim 1, wherein pressure in the majority of the heatedprocess zone is held at ambient reservoir pressure by injecting into theprocess zone steam, non-condensing gas, or a hydrocarbon solvent in avaporized state or a mixture thereof.
 9. The method of claim 8, whereinthe solvent is one of a group of ethane, propane, butane or a mixturethereof.
 10. The method of claim 8, wherein the solvent is mixed with adiluent gas.
 11. The method of claim 10, wherein the diluent gas isnon-condensable under the process conditions.
 12. The method of claim11, wherein the non-condensable diluent gas has a lower solubility inthe hydrocarbons than the saturated hydrocarbon solvent.
 13. The methodof claim 12, wherein the diluent gas is one of a group of methane,nitrogen, carbon dioxide, natural gas or a mixture thereof.
 14. Themethod of claim 1, wherein the method further includes injecting ahydrogenizing gas into the wellbore and thus into the fluids in theprocess zone to promote hydrogenation and thermal cracking reactions ofat least a portion of the hydrocarbons in the process zone.
 15. Themethod of claim 14, wherein the hydrogenising gas consists of one of thegroup of H2 and CO or a mixture thereof.
 16. (canceled)
 17. The methodof claim 14, wherein a metal-containing catalyst is used to catalyzesaid hydrogenation and thermal cracking reactions.
 18. The method ofclaim 17, wherein the catalyst is contained in a canister in tubinginside of the wellbore.
 19. The method of claim 1, wherein the proppantparticles in the inclusions include the catalyst for the hydrogenationand thermal cracking reactions.
 20. The method of claim 1, wherein thesecond depth of the open section of the wellbore is above the firstdepth.
 21. The method of claim 1, wherein a portion of the formation inwhich the first inclusion is formed has a Skempton B parameter greaterthan 0.95 exp(−0.04 p′)+0.008 p′, where p′ is a mean effective stress inMPa at the depth of the first inclusion and the water saturation in theformation pores is greater or equal to 10%.
 22. A hydrocarbon productionwell in a subterranean formation of weakly cemented sediments having anambient reservoir pressure and temperature comprising: a) asubstantially vertical bore hole in the formation to a first depth; b)an injection casing grouted in the bore hole to create a substantiallyvertical wellbore, the injection casing being radially expandable by theintroduction of a fluid; c) a vertical first inclusion in the formationcreated by the fluid delivered into the injection casing with sufficientpressure to dilate the injection casing and to create the firstinclusion in the formation, wherein the first inclusion is filled withthe fluid including electrically conductive proppant particles andwherein the first inclusion is oriented in the formation in a firstpreferential direction extending from and in communication with thesubstantially vertical wellbore d) an open section of the wellborelocated at a second depth displaced from the first depth; e) means formaintaining a reduced pressure at the open section; f) the firstinclusion extending from the first depth to the second depth; and g)electrodes placed in the wellbore for passing an electric currentthrough the inclusion for heating the formation in a process zone in thevicinity of the first inclusion and thereby producing the heatedhydrocarbons up the wellbore from the formation.
 23. The hydrocarbonproduction well of claim 22, wherein the second depth of the opensection of the wellbore is below the first depth.
 24. The hydrocarbonproduction well of claim 22, wherein the production well includes aplurality of inclusions propagated at varying azimuths.
 25. Thehydrocarbon production well of claim 22, wherein the proppant particlesrange in size from #4 to #100 U.S. mesh and are ceramic beadssubstantially coated with an electrically conductive resin.
 26. Thehydrocarbon production well of claim 25, wherein the resin is phenolformaldehyde containing fine graphite particles and is heat hardenable,with resin present in an amount sufficient to consolidate the proppant,but insufficient to fill the openings between the proppant.
 27. Thehydrocarbon production well of claim 22, wherein the proppant particlesrange in size from #4 to #100 U.S. mesh and are selected from a group ofconductive materials such as metals, melt alloys, metal oxides, metalsalts, metal-containing catalysts, calcined petroleum coke or graphitebeads, green or black silicon carbide, boron carbide or a mixturethereof.
 28. The hydrocarbon production well of claim 22, wherein theproppant particles range in size from #4 to #100 U.S. mesh and areselected from a group of non-conductive materials such as ceramics,glass and sands coated with a conductive layer either being metal, metaloxide, metal salts, conductive resins or mixtures thereof.
 29. Thehydrocarbon production well of claim 22, wherein pressure in themajority of the heated process zone is held at ambient reservoirpressure by injecting into the process zone steam, non-condensing gas,or a hydrocarbon solvent in a vaporized state or a mixture thereof. 30.The hydrocarbon production well of claim 29, wherein the solvent is oneof a group of ethane, propane, butane or a mixture thereof.
 31. Thehydrocarbon production well of claim 29, wherein the solvent is mixedwith a diluent gas.
 32. The hydrocarbon production well of claim 31,wherein the diluent gas is non-condensable under the process conditions.33. The hydrocarbon production well of claim 32, wherein thenon-condensable diluent gas has a lower solubility in the hydrocarbonsthan the saturated hydrocarbon solvent.
 34. The hydrocarbon productionwell of claim 33, wherein the diluent gas is one of a group of methane,nitrogen, carbon dioxide, natural gas or a mixture thereof.
 35. Thehydrocarbon production well of claim 22, wherein the production wellfurther includes means for injecting a hydrogenizing gas into thewellbore and thus into the fluid in the process zone to promotehydrogenation and thermal cracking reactions of at least a portion ofthe hydrocarbons in the process zone.
 36. The hydrocarbon productionwell of claim 35, wherein the hydrogenising gas consists of one of thegroup of H2 and CO or a mixture thereof.
 37. The hydrocarbon productionwell of claim 35, wherein a metal-containing catalyst is used tocatalyze said hydrogenation and thermal cracking reactions.
 38. Thehydrocarbon production well of claim 37, wherein the catalyst iscontained in a canister in tubing inside of the wellbore.
 39. Thehydrocarbon production well of claim 22, wherein the proppant particlesin the inclusion include the catalyst for the hydrogenation and thermalcracking reactions.
 40. The hydrocarbon production well of claim 22,wherein the second depth of the open section of the wellbore is abovethe first depth.
 41. The hydrocarbon production well of claim 22,wherein a portion of the formation in which the first inclusion isformed has a Skempton B parameter greater than 0.95 exp(−0.04 p′)+0.008p′, where p′ is a mean effective stress in MPa at the depth of the firstinclusion and the water saturation in the formation pores is greater orequal to 10%.